This invention provides a system and method for remediation of excavated contaminated spoil, using a sorbent in a verified process of testing and analysis of spoil before and after remediation and of adjusting amounts of sorbent and supplemental water mixed with contaminated spoil.
Digging into the Earth—mining, drilling, excavating, and dredging—is a method of obtaining materials and energy and of shaping the built environment. Such digging produces spoil, or removed earth, rock, and sludge, in the form of cuttings, tailings, gangue, overburden, interburden, and waste. Such spoil might be contaminated with toxins and carcinogens such as radioactive materials, heavy metals, hydrocarbons, and other deleterious substances harmful to terrestrial and aquatic plant and animal life either directly or indirectly. If such contaminated spoil is not properly remediated, then the contaminates are likely to migrate out of the spoil and into the environment, as either airborne particles or aterborne suspensions or solutions.
The handling of spoil by digging and drilling operators is highly regulated, and improper handling of spoil is subject to fines and penalties.
Construction aggregate is coarse particulate material such as sand, gravel, crushed stone, slag, recycled concrete, and geosynthetic aggregates used in construction as a reinforcing component and a low-cost extending component of composite materials such as concrete, and as a stable, water-conductive foundation, base, or bed material for roads, drains, buildings, and other construction.
Organic wastes can be destroyed by incineration at high temperatures; however, if the waste contains heavy metals or radioactive isotopes, these must be separated and stored, as they cannot be destroyed. The method of storage will seek to immobilize the toxic components of the waste.
Contaminated spoil is often generated in remote mining, drilling, excavating, and dredging sites. If remediation of such contaminated spoil is to be performed in an off-site facility, then the heavy, bulky, contaminated spoil must be transported in its contaminated state to the off-site facility, which is an expensive and potentially dangerous operation. On-site remediation techniques have the advantage of not requiring transport of contaminated spoil, but existing on-site techniques have the disadvantages of a much greater chance of techniques being performed incorrectly in the field by on-site personnel using on-site equipment, as opposed to personnel and equipment in an off-site, central remediation facility, and on-site techniques and operations are often insufficiently documented to provide verifiable data for review by in-house environmental-quality managers and governmental regulators.
There exists a need for a system and method providing controlled verified remediation of excavated contaminated spoil which can be set up on-site at remote locations, which analyzes each batch of contaminated spoil and analyzes the remediating agent, which applies the proper amount of remediating agent and the proper amount of additional water according to the analysis of the contaminated soil and the remediating agent, and which analyses and verifies the resulting remediated aggregate.
Various patents discuss the use of zeolite as a cementitious substance for encapsulating drill cuttings and the use of zeolite in wash water as a surfactant, as a catalyst, etc.
U.S. Pat. No. 5,711,383 issued on Jan. 27, 1998 to Dralen T. Terry et al. for “Cementitious Well Drilling Fluids and Methods” discloses an invention that provides cementitious well drilling fluids and methods of drilling subterranean well bores. The drilling fluids are basically comprised of water, a water viscosity increasing material and a cementitious material which when deposited on the walls of the well bore as a part of the filter cake thereon consolidates the filter cake into a stable mass that readily bonds to a cementitious material slurry subsequently placed in the well bore. The methods of drilling a subterranean well bore are basically comprised of the steps of preparing a drilling fluid of the invention and drilling a subterranean well bore using the drilling fluid. The consolidated filter cake layers have the physical properties required to prevent pressurized fluid migration in the annulus after the annulus is cemented. A variety of cementitious materials can be utilized in the drilling fluid in accordance with this invention. For example, the cementitious material may be any of the various hydraulic cements which are commonly utilized, both normal particle size and fine particle size. Examples of some of such cements are blast furnace slag, Portland cement and mixtures thereof. Another cementitious material which can be utilized is comprised of a silicious containing substance combined with an activator such as hydraulic cement, lime or an alkali. Suitable silicious containing substances include silicates, amorphous silica, e.g., fumed silica and colloidal silica, rice hull ash, zeolites and volcanic glass.
U.S. Pat. No. 6,039,128 issued on Mar. 21, 2000 to Siro Brunato for “Method and System for Obtaining Core Samples During the Well-Drilling Phase by Making Use of a Coring Fluid” discloses a method and system for obtaining core samples using a coring fluid. During the drilling phase of hydrocarbon wells and the like, drilled with existing drilling systems, the bit that drills the well is driven by a string of rotating pipes and drilling mud is introduced in the rotating pipes. The drilling mud rises carrying with it the cuttings produced by the drill bit. Alternatively, the rotating pipes can be removed and a special piece of equipment called a core barrel is mounted thereon. The rotating pipes thus equipped for collection of the “core” are then lowered into the well. When the rotating pipes are at the bottom of the hole, a sufficient volume of a colloidal, viscous coring or embedding fluid is introduced into the mud circuit to encapsulate a sample of the cuttings, for lifting to the surface and subsequent analysis. The fluid prevents the cuttings from being altered by the drilling mud. In order to obtain core samples of underground formations, drilling and mud circulation in the bore are momentarily suspended, while a certain volume of coring matrix. fluid, that is to say a fluid with an adhesive effect that serves to encapsulate the cuttings, is introduced into the mud circuit at surface. Normal mud circulation is then resumed, pushing the matrix fluid to the well bottom, after which drilling is resumed, so that the matrix fluid passing through the. nozzles in the drill bit hits the cuttings in their virgin state as they are formed and incorporates them a gelatinous mass, protecting them from direct contact with the mud and thus avoiding the washing effect. The cuttings thus coated by the matrix fluid and pushed upward by the mud circulation reach the surface and are collected and analyzed.
U.S. Pat. No. 6,702,044 issued on Mar. 9, 2004 to B. Raghava Reddy et al. for “Methods of Consolidating Formations or Forming Chemical Casing or Both While Drilling” discloses methods of consolidating formations or forming chemical casing or both while drilling. One method of the invention comprises drilling a well bore with a drilling fluid comprised of water, a polymeric cationic catalyst which is absorbed on weak zones or formations formed of unconsolidated clays, shale, sand stone and the like, a water soluble or dispersible polymer which is cross-linked by a thermoset resin and causes the resin to be hard and tough when cured, a particulate curable solid thermoset resin, a water soluble thermoset resin, and a delayed dispersible acid catalyst for curing the solid and water soluble resins. The drilling fluid forms a filter cake on the walls of the well bore that cures and consolidates the unconsolidated weak zones and formations penetrated by the well bore so that sloughing is prevented and forms a hard and tough cross-linked chemical casing on the walls of the well bore. According to the method, one or more insoluble chemical casing reinforcing materials are selected from the group consisting of carbon fibers, glass fibers, mineral fibers, cellulose fibers, silica, zeolite, alumina, calcium sulfate hemihydrate, acrylic latexes, polyol-polyesters and polyvinyl butyral.
U.S. Pat. No. 7,147,067 issued on Dec. 12, 2006 to Donald A. Getzlaf for “Zeolite-Containing Drilling Fluids” discloses methods and compositions for wellbore treating fluids, especially drilling fluids that comprise zeolite and a carrier fluid. In this patent, zeolite is used as a suspending agent in a drilling fluid, whereby the drilling fluid has sufficient carrying capacity and thixotropy to transport cuttings through the annulus and out to the surface. The zeolite acts as a suspending agent for one or more of cuttings, a weighting agent, and loss circulation material. Portions of a zeolite-containing drilling fluid are left on the walls of a wellbore as part of a filter cake, and/or in permeable areas affecting the wellbore, such as fissures, fractures, caverns, vugs, thief zones, low pressure subterranean zones or high pressure subterranean zones. According to such an embodiment, the zeolite in the portions of the drilling fluid left in the wellbore acts as a settable material, which can be caused to set by an activator. According to one embodiment, a subsequent composition that contains at least one activator is pumped into the wellbore to come into contact with the drilling fluid left therein. In one such embodiment, the subsequent composition containing at least one activator is a treating fluid, such as a mud, pill, or spotting fluid, and is pumped into the wellbore prior to primary cementing operations. According to another embodiment, the subsequent composition containing at least one activator is a cement slurry pumped into the wellbore during cementing operations. When the activator in the subsequent composition contacts the drilling fluid in the filter cake and/or permeable areas, the activator causes the zeolite in the drilling fluid to set. In addition, when the subsequent composition is a cement slurry, as the cement slurry sets, the activator therein diffuses into the drilling fluid left in the filter cake and/or permeable areas in the wellbore. The activator is present in the subsequent composition in a compressive strength developing amount, and may be one or more of calcium hydroxide, calcium oxide, calcium nitrate, sodium silicate, sodium fluoride, sodium silicofluoride, magnesium silicofluoride, zinc silicofluoride, sodium carbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, sodium sulfate, or mixtures thereof. Selection of the type and amount of an activator(s) largely depends on the type and make-up of the composition in which the activator is contained, and it is within the means of those of ordinary skill in the art to select a suitable type and amount of activator.
U.S. Pat. No. 8,227,381 issued on Jul. 24, 2012 to Klin A. Rodrigues for “Low Molecular Weight Graft Copolymers for Scale Control” discloses a low molecular weight graft copolymer comprising a synthetic component formed from at least one or more olefinically unsaturated carboxylic acid monomers or salts thereof, and a natural component formed from a hydroxyl-containing natural moiety. The number average molecular weight of the graft copolymer is about 100,000 or less, and the weight percent of the natural component in the graft copolymer is about 50 wt % or greater based on total weight of the graft copolymer. Processes for preparing such graft copolymers are also disclosed. A variety of adjunct ingredients can be used in the cleaning formulations described in this patent. Useful adjunct ingredients include, but are not limited to, aesthetic agents, anti-filming agents, antiredeposition agents, anti-spotting agents, beads, binders, bleach activators, bleach catalysts, bleach stabilizing systems, bleaching agents, brighteners, buffering agents, builders, carriers, chelants, clay, color speckles, control release agents, corrosion inhibitors, dishcare agents, disinfectant, dispersant agents, draining promoting agents, drying agents, dyes, dye transfer inhibiting agents, enzymes, enzyme stabilizing systems, fillers, free radical inhibitors, fungicides, germicides, hydrotropes, opacifiers, perfumes, pH adjusting agents, pigments, processing aids, silicates, soil release agents, suds suppressors, surfactants, stabilizers, thickeners, zeolite, and mixtures thereof.
U.S. Pat. No. 8,356,678 issued on Jan. 22, 2013 to Ramon Perez-Cordova for “Oil Recovery Method and Apparatus” discloses a method and apparatus for recovering oil from oil-containing sorbents, such as drill cuttings obtained from drilling with an oil-based mud. The method includes peptizing the substrate with an acid reagent and direct thermal desorption with combustion effluent gases at high temperature under turbulent mixing conditions. Another method disclosed includes upgrading the oil in the substrate to improve one or more of the properties of the recovered oil relative to the oil in the substrate, such as lower aromatics content, lower sulfur content, lower functional group content, higher saturates, higher viscosity, higher viscosity index, and any combination thereof. The apparatus provides for efficient recovery of oil from the substrate with a short residence time, high through-put, low residual oil content in the treated solids and/or high percentage of oil recovery. The apparatus may be transported to a remote location for on-site treatment of drill cuttings or other oil-containing solids. In one embodiment, the oil-based drilling cutting or other substrate may act as a catalyst or as a support for catalysts, e.g., the peptization with acid may expose or form catalytically active surfaces in the sorbent material. In a further embodiment, the oil-based drilling cuttings or other substrate may be amended by the addition of a catalyst such as one or more of zeolites, aluminates, silicates, aluminum silicates, noble metals, etc., added in the peptization step or in the thermal desorber.
U.S. application Publication Number 2014/0349894 published on Nov. 27, 2014 to Lirio Quintero et al. for “Nanofluids and Methods of Use for Drilling and Completion Fluids” discloses nanomaterial compositions that are useful for applications in drilling and completion fluids as enhancers of electrical and thermal conductivity, emulsion stabilizers, well bore strength improvers, drag reduction agents, wettability changers, corrosion coating compositions and the like. These nanomaterials may be dispersed in the liquid phase in low volumetric fraction, particularly as compared to corresponding agents of larger size. Nanofluids (fluids containing nano-sized particles) may be used to drill at least part of the wellbore. Nano fluids for drilling and completion applications may be designed including nanoparticles such as carbon nanotubes. These fluids containing nanomaterials, such as carbon nanotubes, meet the required rheological and filtration properties for application in challenging HPHT drilling and completions operations. Nanoparticles expected to be useful components of completion fluids include nanosilica, nano-alumina, nano-zinc oxide, nano-boron, nano-iron oxide, zeolites carbonates, piezoelectric crystals, pyroelectric crystals and combinations thereof. Other new potential nanoparticles useful as lost circulation additives include, but are not necessarily limited to, nanoparticles physically or chemically bonded to porous or non-porous rnicroparticles (particle size greater than 100 nm), which may impart some properties of the nanoparticles onto the microparticles. Functional groups on nano-sized particles expected to be useful to prevent lost circulation includenano-silica, nano-alumina, nano-zinc oxide, nano-boron, nano-iron oxide, zeolites carbonates, piezoelectric crystals, pyroelectric crystals and combinations thereof.
U.S. application Publication Number 2014/0371113 published on Dec. 18, 2014 to Gary Fout et al. for “Drilling Fluid Processing” discloses a method of processing a return oil based drilling fluid which includes centrifuging a primarily fluids phase at a first speed and separating the primarily fluids phase into a first effluent and a first residual, centrifuging the first effluent at a second speed and separating the first effluent into a second effluent and a second residual, and centrifuging the second effluent at a third speed and separating the second effluent into a third effluent and a third residual. A surfactant, a polymer, combinations of surfactant(s) and polymer(s) and/or a wash water may be added to one or more of the return oil-based drilling fluid, the primarily fluids phase, the primarily solids phase, the first effluent, the second effluent, and the third effluent. The method of processing a return oil-based drilling fluid includes the steps of dividing the return oil-based drilling fluid into a primarily fluids phase and a primarily solids phase; centrifuging the primarily fluids phase at a first speed and separating the primarily fluids phase into a first effluent and a first residual; centrifuging the first effluent at a second speed, the second speed higher than the first speed, and separating the first effluent into a second effluent and a second residual; and centrifuging the second effluent at a third speed, the third speed higher than the second speed, and separating the second effluent into a third effluent and a third residual. In another aspect, embodiments disclosed in the application relate to a method of processing a return oil-based drilling fluid including adding a volume of a base oil fluid to the return oil-based drilling fluid, wherein the ratio of the volume of base oil fluid added to a volume of the return oil-based drilling fluid is between about 0.1 and 0.4; mixing the base oil fluid with the return oil-based drilling fluid to form a diluted return oil-based drilling fluid; adding a surfactant to the diluted return oil-based drilling fluid; and adding a polymer to the diluted return oil-based drilling fluid. In another aspect, embodiments disclosed in this application relate to method of processing a return oil-based drilling fluid including adding a base oil fluid to a primarily solids phase of the return oil-based drilling fluid, wherein a ratio of a volume of the base oil fluid added to a volume of the primarily solids phase is between 0.1 and 0.2; separating the primarily solids phase into diluted separated fluids and separated solids; adding a wash water to the separated solids; and removing treated solids from the wash water. Chemical additives that may be used in the wash water include surfactants; sodium silicate, zeolites, and other additives useful in the treatment of drilling waste. In some embodiments, the wash water may include biosurfactants which may include oil-digesting microbes. Such microbes digest organic contaminates on surfaces and in soils and convert hydrocarbons, oils, and greases into non-toxic compounds.